ML20046A260

Safety Sys Functional Assessment, Low Pressure Core Spray & RCIC Sys

ML20046A260
Person / Time
Site:	Grand Gulf
Issue date:	06/18/1993
From:	Gura R OGDEN ENVIRONMENTAL & ENERGY SERVICES CO. (FORMERLY
To:
Shared Package
ML20046A259	List: ML20046A258 ML20046A260
References
NUDOCS 9307270161
Download: ML20046A260 (57)

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l GRAND GULF NUCLEAR POWER PLANT SAFETY SYSTEM FUNCTIONAL ASSESSMENT LOW PRESSURE CORE SPRAY AND REACTOR CORE ISOLATION COOLING SYSTEMS Prepared for:

Entergy Operations Inc.

Port Gibson, Mississippi r

Prepared by:

Ogden Environmental and Energy Services Co., Inc.

Philadelphia Operations 1777 Sentry Parkway West Abington Hall, Suite 300 Blue Bell, PA 19422

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R. L. Gura, Team Leader Date b -lk~ N i

9307270161 930723 T?

PDR ADOCK 05000416

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GRAND GULF NUCLEAR POWER PLANT SAFETY SYSTEM FUNCTIONAL ASSESSMENT LOW PRESSURE CORE SPRAY A.ND REACTOR CORE ISOLATION COOLING SYSTEMS Table of Contents Section

.Pm l.0 IIACKGROUND 1

2.0 METIIODOLOGY l

3.0 TEAM COMPOSITION 2

4.0 SCIIEDULE OF ACTIVITIES 3

5.0 GENERAL CONCLUSIONS 4

6.0 SPECIFIC DISCIPLINE SUMMARIES 5

6.1 Mechanical Systems Design 5

6.2 Electrical Design 8

6.3 Instrumentation and Control Design 8

6.4 Surveillance and Testing 10 6.5 Maintenance 12 6.6 Operations 12 APPENDIX A -- ASSESSMENT OBSERVATIONS iii i

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1.0 BACKGROUND

The four members of the BWR-6 Owners Group contracted with Ogden Environmental and Energy Services Co., Inc. (Ogden) to conduct an operational readiness assessment of the low pressure core spray (LPCS) and the reactor core isolation cooling (RCIC) systems at their respective nuclear plants. This assessment was conducted at Entergy Operations Inc.'s Grand

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Gulf Nuclear Power Plant.

The scope of the assessment included the LPCS and RCIC systems, ac and de power distribution equipment to support LPCS and RCIC, related instrumentation and controls, and ventilation systems for the LPCS and RCIC pump rooms.

The assessment used the SSFI vertical-slice techniques, criteria, and schedule of activities guidelines of Chapter 2515 for NRC Inspection, Appendix D, to determine:

1.

If the systems were capable of performing their safety functions as required by the design basis.

2.

If the as-built design and installation of the systems are consistent with the current design / licensing basis requirements.

3.

If the current systems testing is adequate to demonstrate that the systems would perform all of their required safety functions.

4.

If operations, maintenance, modifications, surveillance, and test documentation (including procedures) completely and accurately support a determination that the systems are capable of performing their safety functions.

5.

If the training of operations and maintenance department personnel is adequate to ensure proper operation and maintenance'of the systems.

6.

If human factors considerations and procedures are adequate to ensure proper system operations (normal, abnormal, emergency conditions).

7.

If QA, QC, and training are adequate to ensure that the systems will fulfill the safety functions required by their design basis.

2.0 METIIODOLOGY A safety system functional assessment (SSFA) is an interactive assessment in which a team of highly qualified and experienced inspectors focus on a sample system or systems over a 6-to 8-week period. The team of four Ogden inspectors, assisted by four members from Grand Gulf, examined plant activities in essentially four areas: design, operations, testing, and maintenance. The assessment methodology relies upon two basic principles:

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Through the daily interaction of a relatively small number of senior, experienced inspectors, deficiencies can be identified that otherwise may remain undetected.

2.

By conducting a detailed review of a sample system (also called deep vertical review), conclusions can be drawn as to the overall plant design process, operations, and management controls.

Prior to commencing the assessment, an assessment plan was prepared. The intent of the assessment plan was to provide a framework to answer the following questions:

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How is the system operated compared with how it was designed to operate?

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Have modifications since lhe plant was licensed altered the design in a manner i

such that it may not function as expected?

3.

Are system compcnents properly maintained?

4.

Does post-modification and post-maintenance testing confirm the readiness of the system if called upon?

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Does surveillance testing confirm the readiness of the system if called upon? Do acceptance criteria accurately reflect the design basis?

6.

Have the operators been properly trained to operate the system? Are modifications accurately reflected in training documents?

7.

Are management control programs effective to ensure that the system will function on demand?

The assessment plan was provided as guidance to the reviewers, not as a rigid checklist but as a starting point for the various directions that the assessment might take. Where potential weaknesses were identified, the assessment was intensified in those areas to determine the extent of actual weakness. In addition, the review was not limited to the licensing basis of the plant, but was often extei.ded beyond the original licensing basis in order to determine the functionality of the system.

3.0 TEAM COMPOSITION The assessment team members were as follows:

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.c Position Insnector Company Team Leader /I&C/ Electrical R. Gura Ogden Surveillance R. Boyd Ogden Mechanical Systems M. Bandeira Ogden Maintenance R. DeNight Ogden Operations B. G. Jones Entergy I&C B. Higginbotham Entergy Assessment Coordinator C. H. McCaa Entergy Observer O. L. Grice Entergy 4.0 SCIIEDULE OF ACTIVITIES Week 1 Develop Assessment Program Plan Start 4/12/93 -

Comp. 4/16/93 i

Obtain Key System Documents l

Preparation by Design Team Members at Ogden Offices Weeks 2, 3 Entrance Meeting at Grand Gulf Start 4/19/93 Commence Design Review Start Maintenance, Testing, and Start 4/19/93 Opemtio;s Review Continue Design Review Comp. 4/30/93 Week 4 Continue Design and Testing Review Start 5/3/93 in Ogden office (Grand Gulf team members continue review onsite)

Comp. 5/7/93 Week 5 Design Team Returns to Grand Gulf Start 5/10/93 -

to Continue Design Review Comp. 5/14/93

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Site Team Continues Onsite Review Exit Meeting On Site 5/14/93 Weeks 6, 7 Complete Technical Review, Start 5/17/93 -

Finalize Observations, Comp. 5/28/93 and Prepare Draft Report 3

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Submit Draft Report 5/28/93 Wecks 8, 9 Review of Draft Report by Entergy Start 5/31/93 -

Comp. 6/11/93 Week 10 Issue Final Report 6/18/93 5.0 GENERAL CONCLUSIONS From 4/19/93 to 5/14/93, the combined Ogden and Entergy assessment team performed a detailed technical assessment of the LPCS and RCIC systems at the Grand Gulf Nuclear Power Plant.

Based upon the Assessment Observations, and the specific discipline area summaries that will be presented, the following general conclusions are offered.

1.

The LPCS and RCIC systems were found to be functional in that there were no Assessment Observations to conclude that the system would fail to perform its intended safety function.

2.

In view of the potential impact on the performance of the system, the issues identified in certain specific observations should be technically evaluated and resolved as soon as possible. These observations are:

RCIC turbine overspeed setpoint may be set too high, which may result

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in RCIC pump discharge piping pressurization beyond design values or pump cavitation. [See Assessment Observation MECH-01]

Inconsistencies between design values for the same parameters are found in various input documents. [See Assessment Observation MECH-02]

Insulation is not installed on certain LPCS and RCIC system piping in the LPCS and RCIC rooms as assumed in heat load calculations. [See Assessment Observation MECH-04]

The surveillance procedure fails to adequately verify each of the RPV low pressure instrument channel relay contacts; the surveillance procedure does not verify that both relays in the selected logic combination are functional. [See Assessment Observation TEST-02]

During the assessment, the team noted the following strengths and weaknesses:

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Strengths:

The plant personnel with whom the team interfaced were very cooperative and very knowledgeable in their assigned areas.

The information requested by the team was in all cases readily available for review.

The preventive maintenance program is complete and strong.

The surveillance testing program is very comprehensive.

t I&C calculations are well defined and thorough.

Weaknesses:

Housekeeping in the LPCS and RCIC pump rooms was poor compared with the main areas of the plant.

P A number of inconsistencies were found between design documents.

There is a lack of attention to detail in design documents.

6.0 SPECIFIC DISCIPLINE SUMMARIES The following sections contain a summary of each discipline's review, along with a summary of the significant Assessment Observations.

6.1 MECIIANICAL SYSTEMS DESIGN 6.1.1 Review and Approach In the area of mechanical design, the team reviewed a wide range of design documentation related to the design of the LPCS, RCIC and support systems (e.g., the LPCS and RCIC pump room HVAC). Examples of the reviewed documentation are:

Portions of the Grand Gulf UFSAR, applicable to the RCIC and LPCS systems, were reviewed to identify regulatory commitments.

Piping and instrumentation drawings, system descriptions, and the system design criteria manual were reviewed to assess system design requirements.

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s Calculations were reviewed to determine whether the appropriate design assumptions were made from the design input documents and also to determine whether the results attained were reasonable.

Mechanical engineering standards were reviewed to assess program development -

and implementation.

Some of the plant maintenance and operating procedures were reviewed for accuracy of design information input.

Temporary modifications, LERs, Regulatory Issues, and DCP lists were, at the very least, reviewed to determine programmatic program implementation.

Selective items within these lists were further evaluated to determine correct implementation of design parameters.

In general, the team found that the reviewed documentation provided a comprehensive design basis for the LPCS, RCIC, and supporting systems. Design documentation and design analyses were generally retrievable and easy to follow, and the basis and conclusions were i

casily determined. Engineering personnel and the field personnel involved with programmatic areas were knowledgeable of their area of expertise and aware of the safety and engineering issues involved.

6.1.2 Summary of Sienificant Findings In the area of mechanical design, several Assessment Observations related to the design of the LPCS and RCIC systems were identified. The team does not believe that any of these issues are of safety significance because of design redundancy or design conservatism. The issues were:

6.1.2.1 RCIC turbine overspeed trip setpoint may be set too high to provide pump j

protection from cavitation and piping protection from over-pressurization.

The RCIC turbine's trip setpoint may be too high. If a turbine overspeed occurs with the system in the minimum flow configuration, there may be the possibility of pressurizing the RCIC pump discharge piping beyond design pressures. In addition, if the turbine overspeeds while injecting into the reactor vessel, there is a potential of cavitation within the pump due to loss of net positive suction head (NPSH). [See Assessment Observation MECH-Ol]

6.1.2.2 A field walkdown of the LPCS and RCIC pump rooms determined that insulation is not installed as assumed in the heat load calculation. [See Assessment Observation MECH-04]

Because the LPCS and RCIC insulation does not meet the design assumptions in the design calculations, it is possible that the room temperatures attainable under certain accident scenarios may exceed the design temperatures in the rooms. A review should be performed to 6

determine whether sufficient margin exists in the room coolers to ensure that the room and equipment design temperatures are not exceeded.

6.1.2.3 Several issues were found that could potentially result in less conservative assumptions about the setting of motor operated valve (MOV) setpoints on the LPCS and RCIC system valves.

The values for maximum required differential pressure across some MOVs listed in Mechanical Standard MS-25 for MOV torque and limit switches are less conservative than those listed in the System Design Criteria for the same valves.

There are (to date) 13 MOVs that could not be set to a valve factor of 0.5. Some of these valves are set to a valve factor of 0.3, which the NRC, through testing, determined may not be conservative. An evaluation justifying the acceptability of these valves operating with a valve factor as low as 0.3 does not currently exist.

The practicability analysis to determine individual valve testing or selecting a valve or valves representative of a group has, to date, not been formally documented.. A formal documented review is required to ensure that the valves selected as the representative valves for that group or family are, from an engineering standpoint, bounding valves for each family.

[See Assessment Observation MECH-03]

'l 6.1.2.4 Inconsistencies between design values for the same parameters are found in various design input documents.

The team found several discrepancies between the main branch flows and pressure values stated in GE and Bechtel drawings, calculations, and the UFSAR drawings. [See Assessment Observation MECH-02]

t 6.1.2.5 Formal analysis has not been performed to determine whether valves in the LPCS and the RCIC systems could experience cavitation, which could result in erosion of the carbon steel valve bodies.

In reviewing the response to IE Notice 89-01, the team could not find a formal analysis to determine the potential for cavitation across the carbon steel valves in the LPCS and the RCIC system. Because of the similarity of the fluid operating temperatures for the valves in the systems noted in the IE Notice that have experienced cavitation-related erosion and for the valves in the LPCS and the RCIC system, it is prudent to analyze the LPCS and RCIC valves to determine whether they too can experience cavitation. [See Assessment Observation MECH-05]

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6.2 ELECTRICAL DESIGN 6.2.1 Review and Aporoach in the area of electrical design, the team reviewed applicable administrative and implementing procedures, modification requests, and relevant sections of the Technical Specifications and UFSAR. Electrical documents such as design specifications, one-line diagrams, elementary diagrams, calculations, and relay setting calculations were also reviewed.

A walkdown of the system was made to observe equipment installation and operation.

The team interfaced with electrical design personnel and system engineers. The team found the personnel to be very knowledgeable in the areas discussed.

The RCIC and LPCS electrical hardware reviewed in this assessment focused mainly on the pump motors, batteries, fuses, switchgear; and motor operated valves. The review also encompassed verifying that electrical power sources, protective devices, and controls, including requirements for electrical component and system testing, were sufficient to ensure equipment operation during design basis conditions.

6.2.2 Summary oi Significant Findines In the area of electrical design, there were no significant observations. Howeve.r, one weakness was noted. Specifically, the acceptance criteria in voltage drop calculations were not updated to reflect revised methodology for calculating design input criteria. This issue resulted from a review of the voltage drop calculations on MOVs. [See Assessment Observation ELEC-Ol]

6.3 INSTRbMENTATION AND CONTROL DESIGN 6.3.1 Review and Anoroach In the area of instrumentation and controls, the team performed general reviews of applicable administrative and implementing procedures, piping and instrumentation diagrams, elementary diagrams, logic and schematic diagrams, design change packages, engineering evaluation requests, calibration procedures, setpoint index, setpoint methodology and calculations, and relevant sections of the Technical Specifications and the UFSAR.

Specific areas reviewed and the basis for the review were as follows:

LPCS and RCIC system design criteria and the applicable UFSAR and Technical Specification sections were reviewed for design and licensing requirements relating to instrumentation and controls. Verification was made to determine that there was consistency between these requirements and the design documents and that these requirements are accurately reflected in plant drawings and procedures.

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Design changes were reviewed to verify that the design documents were updated to reflect the implemented changes. This included plant drawings and instrumentation setpoint calculations.

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System walkdowns were performed to observe I&C equipment configuration and operation.

Special emphasis was placed on the review of setpoint calculations. Instrument setpoint methodology was reviewed for prograrnmatic development, control, and implementation of resulting LPCS and RCIC instrument setpoint calculations.

Several instrument setpoint calculations were reviewed in detail to ensure that instrument inaccuracies, drift, and uncertainties were accounted for in the calculations.

The team interfaced with I&C design personnel and system engineers. The team found the personnel to be very knowledgeable in the areas discussed.

Several strengths with respect to the instrument setpoint methodology were noted during the assessment:

The NPE instrument setpoint methodology is well defined and well documented.

The instrument setpoint calculations are easy to follow and are consistent with the approach provided.

The assumptions and the bases are clearly stated in the calculations.

l Specification 3-905.0 provides an excellent tabulation of safety-related setpoint calculations for instruments with active safety functions and also summarizes the results of the calculations.

Instrument Q-list, JS-08, provides references to the supporting documentation for other safety-related setpoints.

6.3.2 Summary of Significant Findings There were no significant findings noted in the instrumentation and controls area.

One minor weakness was identified with respect to the instrument setpoint calculations. Safety-related setpoint calculations for instruments with no active safety function, such as alarms, are not always referenced in Instrument Q-list, JS-08. The team found two examples of this.

I Although these calculations were retrievable from plant records, the team felt that supporting documents for all safety-related setpoints should be readily available for quick reference. This issue should be viewed as program enhancement.

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6.4 SURVEILLANCE AND TESTING 6.4.1 Review and Annroach The review of the surveillance testing of the RCIC (E51) and LPCS (E21) systems included the following:

GE Design Specifications and Data Sheets Technical Specifications and Position Statements Updated Final Safety Analysis Report (UFSAR)

Tech Spec / Surveillance Instruction Cross Reference Matrix System Design Criteria Documents System Descriptions Operations Manual Grand Gulf Maintenance Information System (SIMS)

Commitment Tracking System Surveillance Instructions (including completed test data)

Condition Repons Drawings (P&lDs, Elementary and Schematic Diagrams)

IST Trending Data for the RCIC and LPCS pumps and valves Selected Work Orders (WOs)

Selected Design Modifications The purpose of the review.was to determine if the RCIC and LPCS systems are being tested appropriately to verify system opembility and whether the systems and components can perform their safety-related functions as intended by design. Overall, the assessment team found the surveillance testing program to be very comprehensive and, as_such,~ a strength.

The IST program and trending of IST data were thorough, complete, and also considered a strength.

In addition, the team found a weakness in that there was no specific procedural guidance for the performance of scaling calculations for smveillance procedure setpoints and the calculation documentation for these setpoints was not readily available. The procedures provided to the team by System Engineering were vague with respect to performing setpoint calculations. The team was informed that the calculation documentation was retrievable if requested. This was found to be true for all documentation requested by the team. However, considerable time was required to obtain this information. Additionally, there was no consistency in format for the documentation. The team was informed that a formal document was planned to gather the procedure setpoint information which would be an extension of an NPE specification (GGNS-JS-905.0).

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6.4.2 Summarv of Significant Findings Several Assessment Observations were made in the surveillance and testing area.

The team does not believe any of these observations to be of safety significance. They.

were:

6.4.2.1 Grand Gulf surveillance procedures that' perform channel calibrations (i.e.,

transmitters valved out and back into normal lineup) fail to adequately require verification that the instrument channels have been restored to operational conditions.

i Grand Gulf surveillance procedures, following channel calibration, require the test performer to verify that the tested channel reflects current plant conditions following restoration of the channel to service. The procedures provide no guidance (e.g., comparison with channel indications measuring the same parameter) as to how to perform this verification. Channel checks performed by Grand Gulf surveillance procedures to satisfy Technical Specifications include, where possible, the comparison of channel indications with other instrument channel indications measuring the same parameter. Also, acceptance criteria are provided for the performer to evaluate the operability of the channels. However, the surveillance procedure for-performing calibrations fails to provide such guidance to the performers when performing a channel check after the instrument channel has been restored to service. [See Assessment Observation TEST-01]

6.4.2.2 Failure to perform adequate logic system functional test of the LPCS RPV injection permissive.

The surveillance procedure that tests the LPCS RPV injection valve permissive logic, fails to correctly determine whether the logic operates as designed. By verifying that continuity exists 'or does not exist only after having tripped (reset) a combination of two instrument channels, the test does mt confirm that the individual relay contacts in each instrument channel have actuated. One of the two instrument channel relays could be failed (contact closed) and go undetected because the surveillance procedure does not require verification of each individual channel contact. In addition, if the trip unit in the channel with the failed relay trips (resets) before (after) the other trip unit under test, the failure would not be detected by the test method. The surveillance procedure fails to verify that both relays in the selected logic combination are functional. [See Assessment Observation TEST-02]'

6.4.2.3 Inadequate post-modification testing of MCP 90/1036.

1 MCP 90/1036 installed two new relays to initiate the RCIC turbine exhaust line drain trouble annunciator when the RCIC turbine exhaust drain isolation valve fails to open within 5 seconds after the drain pot high-level setpoint has been reached. A special test was performed to demonstrate that the RCIC turbine exhaust line drain trouble instrumentation performed according to the MCP; however, the relay that indicates valve position (full open, not full open) was not tested to verify that it performs its design function. [See Assessment 11

Observation TEST-03] The relay was tested during the assessment and found to perform its function. QDR 93/100 was issued to document this deficiency.

6.5 MAINTENANCE 6.5.1 Review and Approach The maintenance portion of this assessment included a review of vendor manuals, preventive maintenance procedures, preventive maintenance scheduling, surveillance test procedures, and computerized work summaries on completed work orders. The purpose of the review was to determine if the maintenance requirements specified in the vendor manuals and plant procedures were being implemented in the preventive and corrective maintenance programs, and to assess the effectiveness of the maintenance programs.

Ilased on the review of the maintenance program, the team found no issues that indicate that the RCIC or the LPCS systems are not being maintained in an adequate condition to perform their safety-related and non-safety-related functions.

Implementation of the maintenance program at Grand Gulf appears to be well organized and well executed. The vendor recommendations in component manuals for preventive maintenance and proper lubrication have been implemented within the timeframes set by the manufacturer with some exceptions caused by the imp.racticality and unfeasibility of the recommendation.

6.5.2 Summary of Significant Findinns Although four Assessment Observations were identified, no issues were found that would lead the assessment team to believe that either of the systems would not perform its functions. There were no significant findings in the maintenance area.

The team conducted a walkdown of the RCIC and LPCS systems during which several maintenance and housekeeping concerns were identified. [See Assessment Observation M AINT-01J The team also identified inconsistent torque requirements for the RCIC turbine / pump's bolts and nuts in various documents. [See Assessment Observation MAINT-03).

6.6 OPERATIONS 6.6.1 Review and Approach In the area of operations, the team's review focused on verifying that no contradictory information exists in the following documents for the LPCS and RCIC systems:

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System Operating Instructions Technical Specifications System Descriptions Surveillance Instructions UFSAR Alarm Response Instructions System Design Criteria Vendor Manuals Lesson Plans Alarm Response Instructions GE Operations and Maintenance Instruction.

To evaluate programmatic implementation of design information, a control board walkdown of the RCIC and LPCS systems to verify proper alignment of valves and switches was performed, and Auxiliary Building Rounds sheets and Daily Log books pertaining to the RCIC and LPCS systems were reviewed. Also, Operations personnel were interviewed and the Control Room indicators were inspected to verify readability. The team also evaluated portions of the operator training program lesson plans to assess program updates as a result of design changes.

The team found that the Operations area is well equipped to handle normal and abnormal situations pertaining to the LPCS and RCIC systems.

6.6.2 Summary of Sienificant Findines There was one Assessment Observation in the Operations area.

6.6.2.1 The potential for Operations personnel to become desensitized to conditions requiring immediate evaluation and corrective action as a result of recurring equipment problems.

Persistent sump pump level switch and timer problems may have the potential to desensitize operators to the potential importance of sump pump operations. Sump pump run time could be an indication of leakage as the result of component failure such as LPCS pump seal failure or relief valve lifting. The operators must rely specifically on sump pump run times to assess LPCS pump seal leakage. Therefore, any indication of pump run time or swho misoperation should be immediately investigated for maintenance problems and correcti'.c action initiated to verify the reason for the sump pump runs; that is, whether discrepant timers and/or switches are the cause of run time or if actual leakage is present. The LPCS room sump level Hi-Hi alarm provides entry into Emergency Procedure EP-4. The team identified nine work orders associated with the sump pump timers and seven work orders associated with the sump pump level switches, generated in the past 3 years. [See Assessment Observation OPS-Ol].

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APPENDIX A ASSESSMENT OBSERVATIONS i

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M ECH REVISION: 3 DATE:

6/15/93 ASSESSMENT OBSERVATION AREA:

Mechanical INSPECTOR:

Robert W. DeNight ISSUE:

RCIC turbine overspeed trip setpoint may be set too high to provide pump protection from cavitation and piping protection from overpressurization.

REQUIRENIENT:

The overspeed trip setpoint is 120%

2% of turbine design rated speed, per turbine vendor manual 460000182. The piping's service rating is 1230 psi, per MS 2.

DISCUSSION:

The overspeed trip of the RCIC turbine, component IE51C002, is currently set at 5428 to 5612 rpm, which corresponds to 120%

2% of 4600 rpm. The maximum rated speed for the turbine is actually 4550 rpm. This higher turbine speed results in the elevation of the pump curve, consequently increasing pressure for the same flow rate. As a result of this elevated pump curve, the team has reviewed the following two possible scenarios:

1.

The pump running, as designed, injecting into the reactor 2.

The pump running in the min-flow recirculation path.

If an overspeed of the turbine occurs, due to a governor valve failure, while in scenario 1, the team's concern is the possibility that the pump will run out due to insufficient NPSH at the pump suction. Insufficient NPSH could jeopardize the pump's integrity due to cavitation within the pump.

If an overspeed of the turbine occurs while in scenario 2, the resulting head produced by the RCIC pump, running at a speed of 5612 rpm, would be 4900 ft (2110 psi with H O at 2

100 F). With a pump suction pressure of 0 to 100 psi, the resulting pump discharge

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MECH-01 REVISION: 3 Page 2 pressure would be 2110 to 2210 psi. The discharge piping is rated, per MS-2, at a design rating of 1500 psi and a service rating of 1230/1375 psi (norm / max). The concern in scenario 2 is the overpressurization of the discharge piping beyond the service rating.

The GE purchase specification for the RCIC turbine states that the overspeed setting of the turbine shall be 10 percent above the maximum speed overshoot on quick start, but shall not exceed 120 percent of the maximum normal operating speed.

COMMENTS AS TO SAFETY SIGNIFICANCE:

The team does not feel that this issue is of safety significance. The RCIC system is not considered as a self-redundant system. Its function is redundant by other safety systems.

However, the system's components may be exposed to parameters beyond design parameters and/or damaged if an overspeed scenario, as described above, occurs.

ENTERGY CONTACT:

Bryan Warren ENTERGY RESPONSE:

MNCR 0098/93 has been initiated.

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MECH-02 REVISION: 3 DATE:

6/15/93 ASSESSMENT OBSERVATION AREA:

Mechanical INSPECTOR:

M. O. Bandeira ISSUE:

Inconsistencies between design values for the same parameters are found in various design input documents.

REQUIREMENT:

Design data must be consistent. Consistency between design values is necessary to ensure that design configuration is maintained.

DISCUSSION:

Several examples were found where inconsistencies between design values for similar parameters were found in several design input documents. Examples include the following:

GE drawing 762E467BA, "IAw Pressure Core Spray System Process Diagram,"

provides operating parameters for flow, temperature, and pressure for various LPCS system operating modes. The team has found several discrepancies between the main branch flows stated in the GE drawing and the flows stated in Calculation 1.3.3-Q.

For example:

Mode GE DrawinE

.CalQ A

9100 gpm 8900 gpm B

9530 gpm 8900 gpm F

9100 gpm 8900 gpm Similarly, differences exist with respect to operating pressures between the GE drawing mentioned above and the FSAR Figure 6.3-5. For example, at the LPCS pump suction, the following discrepancies between the two documents were noted:

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MECH-02 REVISION: 3 Page 2 Mode

. Calc FSAR A

20 psia 18.0 psia B

52 psia 33.8 psia C

21.4 psia 18 psia D

18.5 psia 18.4 psia F

18.1 psia 18 psia S

19.6 psia 16.4 psia For the node located at the discharge of the LPCS pump downstream of the LPCS miniflow line, but before the LPCS jockey pump discharge line, the following discrepancies were found:

Mode Calc FSAR A

281 psia 300 psia B

313 psia 305 psia C

473 psia 531 psia D

352 psia 330 psia F

274 psia 295 psia S

-19.6 psia 16.4 psia Discrepancies were also found between the FSAR and Bechtel dmwing SFD-1087 entitled " System Flow Diagram - Low Pressure Core Spray System." For example, discrepancies on the main branch flows were found:

Mode Bechtel Drawine FSAR A

8900 gpm 9100 gpm B

8900 gpm 9530 gpm F

8900 gpm 9100 gpm Similarly, differences in pressure values were found between the Bechtel drawing and the FSAR at the same node.

Mode Bechtel Drawing FSAR A

18.2 psia 16.4 psia B

18.2 psia 18 psia

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MECH-02 REVISION: 3 Page 3 There may be other such discrepancies that exist between these documents and, as such, these documents should be completely reviewed to correct these types of discrepancies.

Also, it should be noted that the existence of three different documents providing the same information, the FSAR, the Bechtel drawing, and the GE drawing, can result in discrepancies between the documents similar to those stated above. Whenever possible, similar design information should be limited to a single design source document to reduce or even eliminate the potential for error.

With respect to the RCIC system, similar types of discrepancies were found. The respective documents on the RCIC system should be reviewed to eliminate the same types of discrepancies.

COMMENTS AS TO SAFETY SIGNIFICANCE:

The team does not believe that a safety significance exists. In the examples above, the team believes that, because of calculational conservatism and physical system configuration, the conclusions reached are valid in spite of the fact that the values used differ from those listed in design documents. Therefore, the team believes that these examples do not constitute any safety significance. However, these examples appear to indicate that there is not always the attention to detail necessary to ensure consistency in design information.

ENTERGY CONTACT:

Bryan Warren and Brent Barfield ENTERGY RESPONSE:

As noted in the discussion of the Assessment Observation, there is a discrepancy in flow rates betweer, the GE Process Diagram (762E467BA) and Bechtel Calculation 1.3.3-Q for modes A, B, and F. However, notes 7C and 11 of the GE drawing clarify this issue by stating the following:

"The flow in modes B and F is less than or equal to the maximum flow that the pump has been tested to by the pump supplier." (Note 7C) f "It is recommended that this orifice be installed if required to limit Dow in Mode A to the value specified or to the maximum flow permitted by Note 7C, 7D (Mode F only) and 7E." (Note 11)

Per Performance Test Curve T-36512-7/7A, the maximum Dow that the pump was tested to was 8900 gpm rather than 9100 gpm as specified on the GE Process Diagram. Bechtel did not revise the GE Process Diagram because it is not in error when notes 7C and 11 are considered.

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MECH-02 REVISION: 3 Page 4 There are several discrepancies between the FSAR Figure 6.3-5 and the Bechtel System Flow Diagram (SFD-1087). The latest revision of the SFD is Revision 3. However, this revision has not been incorporated into the FSAR Figure. NPli, will review the latest SFD revision for accuracy and revise FSAR Figure 6.3-5.

TEAM RESPONSE:

The team concurs with the response provided by Entergy.

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NUMBER:

MECH-03 REVISION: 2 DATE:

6/15/93 ASSESSMENT OBSERVATION AREA:

Mechanical INSPECTOR:

M. O. Bandeira ISSUE:

4 Several issues were found that could potentially result in less conservative assumptions made as to the setting of MOV setpoints on the LPCS and RCIC system valves.

REQUIREMENT:

Motor operated valve (MOV) actuator thrust and torque switch settings must be set at values that will ensure that the valves will actuate as intended under design basis parameters.

DISCUSSION:

Several issues were found as a result of the review performed on the MOV program relating to the MOVs on the LPCS and the RCIC system. They are:

1.

The expected pressure differential across several MOVs in the LPCS system is listed in the System Design Criteria manual as well as in Mechanical Standard MS-25. The System Design Criteria pressure differential values were provided by GE, whereas the values found in Mechanical Standard MS-25 were calculated based on accident scenarios. The issue is that the calculated values are less conservative than the values found in the System Design Criteria (SDC); the calculated values listed in MS-25 are the values that are used to develop MOV actuator settings. The following are the differences found:

Valve S_D_C MS-25 D

F005 1200 psid 529 psid F011 550 psid 538 psid F001 70 psid 37 psid F012 600 psid 536 psid it is not clear what the basis of the SDC calculations is or even if the assumptions differ from those of the MS-25 document.

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NUM11ER:

MECH-03 REVISION: 2 i

Page 2 i

2.

When the MOV actuators are set in the field, an attempt is made to set the actuator torque switches to values that are based on a valve factor of 0.5. By procedure, should it not be possible to set the valves to the corresponding 0.5 values, the valves can be set lower but never below the values corresponding to a valve factor of 0.3.

However, as a result of NRC/INEL tests performed on MOVs, it was determined that the commonly used industry valve factor of 0.3 may not be sufficiently conservative l

to ensure adequate valve actuation. So far, as a result of actual testing at Grand Gulf, it has been determined that there are 13 valves that have not been capable of being set to the values corresponding to the 0.5 valve factor. Although these 13 valves are currently being evaluated for potential modifications, an evaluation that would justify the acceptability of the valves operating under the values corresponding to a valve factor lower than 0.5 has not been performed.

3.

In light of the requirements of the NRC Generic Letter 89-10, a practicality review i

was performed by Grand Gulf on each MOV to determine the practicality of testing l

the valves in the field based on physical limitations and plant operating limitations.

Subsequently, Siemens was commissioned to perform an analysis to segregate the MOVs into families to arrive at an alternate to individual field testing of the valves to confirm adequate MOV actuator setpoints. This study confirmed some of the original testing selections and broadened the original testing scope. The broadened scope of l

the Siemens' study has been under evaluation; there are instances where some of the I

recommended representative valves to be tested were found, based on preliminary j

reviews, not to be practicable due to the physical and plant operating limitations.

The preliminary practicability analysis performed by Grand Gulf has to date not been formally documented. A formal documented review is required to ensure that the valves selected as representative valves are the bounding valves for each family.

Also, where due to limitations valves different from those recommended by Siemens are chosen, assurance that these valves provide the required bounding criteria should be provided formally. A formal document should be developed to provide adequate justification for the selection. It is the team's understanding that this formal document is in the process of being developed.

COMMENTS AS TO SAFETY SIGNIFICANCE:

It is possible that the actuator setpoints on MOVs may not be conservatively set to ensure valve actuation. Setting the setpoints below values necessary to ensure adequate valve i

actuation may result in the system not being capable of operating as designed. However, with respect to the issue of safety significance, the team feels that this is a developing program which the industry, in general, is addressing. Grand Gulf continues to develop their MOV program to resolve MOV issues, such as acceptable valve factor values, individual valve testing, and alternate valve testing.

NUMBER:

MECH-03 REVISION: 2 Page 3 ENTERGY CONTACT:

Jeff Wright, Matt Rohrer, and William White ENTERGY RESPONSE:

The following issues were identified as a result of the review performed on the MOV Program relating to MOVs in the LPCS and RCIC systems.

1.

Differences were identified with valve differential pressure values listed in Mechanical Standard MS-25 and the applicable System Design Criteria.

Response

Maximum differential pressures (MEDP) were calculated for all MOVs within the scope of Generic Letter 89-10 based on worst case conditions for the valves. The resulting MEDPs were included in MS-25. The differential pressures shown in the System Design Criteria (SDC) were extracted from original specifications used for procurement of the valves and represent historical information related to the design capability of the valves. The values listed in the SDC are higher than those in MS-25 indicating that the design of the valves bound the current differential pressure requirements. In other words the valves are acceptable for use in their current application.

2.

Mechanical Standard MS-25 provides torque switch setting information based on a valve factor of 0.5. Information is also provided based on a valve factor of 0.3, and the field is allowed to set the torque switch using the 0.3 data if the 0.5 values cannot be used. The use of a valve factor of 0.3 may not be conservative when the setting is used as a basis for field setting of torque switches on MOVs.

Response

The valves were originally provided by the manufacturer with a valve factor of 0.3.

J This is a common design value used within the valve industry. Some testing by the NRC has been performed which indicates that a 0.3 valve factor may not be conservative under all conditions for some flex wedge gate valves within the nuclear industry. However, since it has not been shown that there is a generic deficiency with the design of all valves, GGNS continues to use the original design value of 0.3 as a minimum for control switch setting of flex wedge gate valves. In an attempt to add conservatism to the original design, switch settings are made based on a target valve factor of 0.5 whenever possible. If a flex wedge gate valve cannot be set up using a 0.5 valve factor, the control switch is configured with criteria based on the minimum value of 0.3, and the valve is identified for possible modification. This program is described in detail in MS-25 and General Engineering Standard GES-06.

NUMBER:

MECH-04 REVISION: 2 DATE:

6/15/93 ASSESSMENT OBSERVATION AREA Mechanical INSPECTOR:

M. O. Bandeira ISSUE:

A field walkdown of the LPCS and RCIC pump rooms determined that insulation is not installed as assumed in the heat load calculation.

1 REQUIREMENT:

To ensure that the systems will operate in accordance with the system design assumptions, the field configuration must be consistent with the design calculations.

i DISCUSSION:

l A review of calculation 3.3.39-Q entitled " Post-LOCA Auxiliary Building Cooling Loads,"

determined that the piping in the LPCS room is assumed to be insulated with 1.5 inches of calcium silicate insulation; this insulation reduces the amount of hea from the piping to the room. A field walkdown of the LPCS room determined that the LPCS pump discharge piping as well as a small section of the pump inlet piping is uninsulated. Therefore, the assumptions in the heat load calculation referenced above do not accurately reflect the design of the system.

Similarly, the exhaust piping on the RCIC turbine located in the RCIC turbine room was found to be, for a significant portion ofits length, uninsulated. Calculation 3.3.39-Q uses the results for the heat loss values from Calculation 3.8.39 which assumes that the exhaust piping is covered with 2.5 inches of insulation. Furthermore, it was determined from the walkdown that the exhaust piping enters the RHR pump room and it had a significant portion of the piping uninsulated. Therefore, since the exhaust piping is not totally insulated as assumed in the design calculations, the heat loads determined in the calculation do not accurately reflect the design of the system. The RCIC room and the other rooms through which the turbine exhaust piping passes should be reviewed for the heat load impact on the rooms.

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P NUMBER:

MECH-04 REVISION: 2 Page 2 A review of the Piping Specification determined that the insulation in both areas of concem listed above is, by the Specification, for " personnel protection." This Specification requirement can be interpreted to mean that because these areas are, for the most part, not easily accessible due to height above the floor, there is no need to insulate these lines.

Based on the fact that the installed connguration does not agree with the design assumptions in the design calculations, it is possible that the room temperatures attainable under certain accident scenarios may exceed the design temperatures in the rooms. A review should be performed to determine whether sufficient margin exists in the room coolers to ensure that the room and equipment design temperatures are not exceeded. The team noted that a survey of the LPCS and RCIC piping insulation was performed after the observation was issued.

I COMMENTS AS TO SAFETY SIGNIFICANCE:

For the RCIC room, a review of calculation 3.3.39-Q appears to indicate that a significant margin exists between the cooling requirements of the room and the cooler cooling capabilities. On the other hand, although some margin exists between the heat gene: cd in the room and the LPCS room cooler hea' rmoval capabilities, without an analysis it is not clear 'vhether the addit' anal heat will stih a within the capabilities of the cooler. In either case, an analysis should be performed to determine the actual heat load addition resulting from the uninsulated piping and whether this added heat load is still within the capabilities of the coolers.

With respect to the issue of safety significance, it should be noted that even if insufficient margin exists in the coolers to remove the additional heat load, the calculations are relatively conservative in that they assume a starting temperature at the start of the LOCA of 150*F, whereas the actual room temperature at the start of the LOCA is much lower than 150 F, which may provide sufficient margin to preclude any safety significance.

ENTERGY CONTACT:

Jeff Wright and Bryan Warren ENTERGY RESPONSE:

MNCR 0106/93 has been initiated.

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NUMBER:

MECH-05 REVISION: 2 DATE:

6/15/93 ASSESSMENT OBSERVATION AREA:

Mechanical INSPECTOR:

M. O. Bandeira ISSUE:

Formal analysis has not been performed to determine whether valves in the LPCS and the RCIC systems could experience cavitation which could result in erosion of the carbon steel valve bodies.

REQUIREMENT:

IE Notice 89-01 was issued to alert the nuclear industry to the potential for carbon steel valve body erosion in safety-related systems. IE Notices, although generally limited to a very specific scope or issue, should be reviewed on the basis of a much broader scope to include applications of components or systems of similar characteristics or experiencing similar operating parameters.

DISCUSSION:

In the review ofIE Notice 89-01 response, the team was not able to find a formal analysis to determine the potential for cavitation across the carbon steel valves in the LPCS and the RCIC systems. Because of the similarity.if fluid operating temperatures between the valves in the systems noted in the IE Notice that have experienced cavitation-related erosion and the valves in the LPCS and the RCIC systems, it is prudent to analyze the LPCS and RCIC valves to determine whether they too can exper:ence cavitation.

I COMMENTS AS 'IO SAFETY SIGNIFICANCE:

The team is of the opinion that this issue does not constitute a safety significance. Grand i

Gulf has a corrosion / erosion program that should provide adequate early indication of developing wall thinning which, if properly extrapolated beyond the immediate area of concern, should broaden the scope of the erosion / corrosion program to include valves and piping exposed to similar operating characteristics.

ENTERGY CONTACT:

Bryan Warren and Scott Martin

NUMBER:

MECH-05

)

REVISION: 2 Page 2 ENTERGY RESPONSE:

No components in the RCIC and LPCS systems have been included in the E/C program because a search of industry experiences has not revealed any E/C initiating phenomena. No valve is being throttled in these systems. In response to NRC Information Notice Number i

89-01, NPE has added five additional locations in the RHR system, each consisting of two (2) new components (valve body and straight piping downstream from the valve) into its monitoring program for RFO6. The selection of these valves was based on industry experience and engineering judgment. These valves are three 18" motor operated globe valves; QlE12-F003B-B and QlE12-F048A-A which are being throttled and QlE12F053A-A for its past throttling situation. The 14" motor-operated globe valve Q1E12F021-B is selected for inspection for other reasons during the same period. These four valves were selected from industry experience of valve body erosion found by Brunswick Stehm Electric Plant, Unit 1 of CP&L Company. The fifth valve is a 4" gate valve QlE12-F086 which was selected from industry experience of valve body erosion found by Hatch Unit 1.

TEAM RESPONSE:

The team generally accepts the response provided by Entergy. It is expected that the current erosion program scope, specifically relating to carbon steel valve body erosion, will be expanded as necessary should indications of valve body erosion become evident in the valves currently being tested.

NUMBER:

ELEC-01 i

REVISION: 1 DATE:

6/15/93 ASSESSMENT OBSERVATION AREA:

Electrical Design INSPECTOR:

R. Gura ISSUE:

Acceptance criteria in voltage drop calculations are not updated to reflect revised methodology for calculating design input criteria.

REQUIREMENT:

ANSI N45.2.ll requires design calculations to accurately reflect revised design criteria.

DISCUSSION:

Engineering calculation EC-Q1L21-90033,-Rev. O, dated 11-12-90, " Division I 125vde Class IE Voltage Drop Study," calcubtes the available voltage at the terminals of those devices on the Division I 125-Vdc battery that are energized during a loss of offsite power and a loss of i

coolant accident with a concurrent loss of the Division I battery chargers.

The calculated minimum available voltage is compared against the minimum required voltage acceptance criteria as specified by the manufacturer. In the case of the motor operated valves, the minimum voltage is 80% of rated except for special cases where the minimum voltage is a function of the valve operator characteristics (reduced voltage factor). Where the calculated minimum voltage is less than the acceptance criteria, justification is provided in Section 6 of the calculation.

The reduced voltage factor (RVF), as calculated in Section 5.6 of calculation EC-Q1L21-90033, relates required torque of the MOV to actual required stem thrust. The valve stem.

thrust values required to stroke MOVs against maximum expected differential pressure in the RCIC system, were obtained from calculation MC-QlE51-90149 Rev. 3, which was subsequently superseded by calculation MC-Qllll-91132. Calculation MC-QlE51-90149 was not identified as being superseded. The stem thrust values relied on assumptions for actuator conditions (valve factor) which may not be accurate.

w NUMBER:

ELEC-01 REVISION: 1 Page 2 For valves E51-F013 and E51-F045, the calculated minimum voltage to deriver the required thrust is 96.25 and 72.25 Vde, respectively. The calculated required minimum voltages from Section 5.6 are used in the computer calculation as acceptance criteria (pages 103 and 27 of Attachment I).

Because of the inaccuracy of the valve factors used in calculation MC-QlE51-90149 to determine required stem thrust, a new calculation MC-Qllll-91133, Rev. 2, was developed to calculate motor output capabilities designated as degraded voltage actuator torque capability (DVAC). The DVAC is derived from the terminal voltagc determined in the voltage drop calculation EC-Q1L21-90033.

A review of calculation MC-Qll11-91133, Rev. 2, was made for valves lE51-F013 and 1-E51-F045. The minimum voltages used to calculate the DVAC for the valves were 102.2 and 107.86 Vde, respectively.

Calculation EC-Q1L21-90033 (Attachment X, p.103 for case T5-T = 21.395 to 105 seconds and Attachment V, p. 27 for case T3 T = 11 to 16 seconds) was the source of the input, but the references were not stated in the calculation. However, the references were available in the reference section.

Calculation 90033 has not been revised to reflect the new methodology for determining the DVAC for MOVs. For example, the calculation of the minimum required voltage should be deleted and the determination of voltage acceptability should also be deleted. The calculation should indicate that the results for MOV terminal voltage are to be used in Standard MS-25.

Standard GGNS-MS-25-0, " Motor Operated Valve Torque and Limit Switches," establishes the general design requirements and operating characteristics for motor operated valves and maintains actuator data including calculated degraded voltage actuator torque capability (DVAC) and minimum required stem thrust. The DVAC is derived from the terminal voltage determined in the voltage drop calculation EC-Q1L21-90033 as stated above. This torque limitation is verified by the field through MOV spring pack displacement at the required stem thrust.

Calculation EC-Q1L21-91009, " Voltage Drop Calculation for RCIC MOVs F022-A, F059A and F068 Motors, also calculates a reduced voltage factor RVF which is used to calculate the minimum required voltage needed for the MOV. The minimum required voltage is then compared with the calculated voltage available as determined by the computer-generated voltage drop calculation. This calculation should also be revised to reflect the use of the DVAC factor to determine adequacy of the calculated voltage available for the MOVs.

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NUMBER:

ELEC-01 REVISION: 1 Page 3 COMMENTS AS TO SAFETY SIGNIFICANCE:

This observation is not safety significant. However, the use of superseded or revised acceptance criteria could lead to an unconservative evaluation of future calculational results.

I ENTERGY CONTACT:

Bryan Warren and Thomas Thornton FNTERGY RESPONSE:

This observation is under evaluation.

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NUMBER:

TEST-01 REVISION: 0 DATE:

4-29-93 ASSESSMENT OBSERVATION AREA:

Surveillance Testing INSPECTOR:

W. R. Boyd ISSUE:

Grand Gulf surveillance procedures that perform channel calibrations (i.e., transmitters valved out and back into normal lineup) fail to adequately require verification that the instrument channels have been restored to operational conditions.

REQUIREMENT:

Following restoration of an instrument channel to service, verification (by performance of a channel check) that the channel has been placed back into service and is operable should be performed.

17-S-01-11, Rev. O, Performance and System Engineering Instruction Section Level Philosophy (Attachment II, I&C Philosophy Information, Generic I&C Guidelines, Item 22) states " Perform a channel check in all calibration procedures after the transmitter has been valved back into normal lineup. If a procedure lifts wires from an instrument.in the loop, perform a channel check at conclusion of procedure."

Technical Specification Definition 1.5 Channel Check states "A CHANNEL CHECK shall be the qualitative assessment of channel behavior during operation by observation. This determination shall include, where possible, comparison of the channel indication and/or status with other indications and/or status derived from independent instrument channels i

measuring the same parameter."

IEEE Std 338-1977, Standard Criteria for the Periodic Testing of Nuclear Power Generating Station Safety System, states in 6.l(4) "The test procedure shall have requirements for confirming that when a test is completed the equipment tested has been restored to its normal operational mode."

DISCUSSION:

Grand Gulf surveillance procedures, following channel calibration, require the test performer to verify that the tested channel reflects current plant conditions following restoration of the

NUMilER:

TEST-01 REVISION: O Page 2 channel to service. The procedures provide no guidance (e.g., comparison with channel indications measuring the same parameter) as to how to perform this verification. Channel checks performed by Grand Gulf surveillance procedures to satisfy Technical Specifications include, where possible, the comparison of channel indications with other instrument channel indications measuring the same parameter. Also, acceptance criteria are provided for the performer to evaluate the operability of the channels. However, the surveillance procedure performing calibrations fail to provide such guidance to the performers when performing a channel check after the instrument channel has been restored to service.

EXAMPLES:

06-IC-1B21-R-0008, Rev. 27, Step 5.20.14 06-lC-1B21-R-2009, Rev. 21, Step 5.16.9 06-IC-1B21-R-0003, Rev. 27, Step 5.79.8 COMMENTS AS TO SAFETY SIGNIFICANCE:

Performance of adequate channel checks following instrument channel calibrations will increase assurance that the instrument channel has been restored to operable conditions.

ENTERGY CONTACT:

Rick Ingram ENTERGY RESPONSE:

System Engineering disagrees with the idea that " Tech Spec" channel checks are required to be performed following the performance of calibration procedures. Satisfaction of IEEE Std. 338-1977, 6.l(4) is accomplished by:

Verification that all test equipmentis removed All bypass switches are returned to Normal All jumpers are removed All lifted leads are landed All failure indicators are reset (status lights, annunciators, computer points)

Grand Gulf's programs require that everything affected by the test be returned to normal configuration to ensure that we meet the requirements of " confirming when a test is completed the equipment tested has been restored to its normal operational mode."

The " channel check" referred to in the philosophy procedure is only an additional good practice to ensure that the equipment is not in a failed condition following restoration to operational mode.

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,a._a NUMIlER:

TEST-01

~

REVISION: 0 Page 3 TEAM RESPONSE:

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The team has reviewed the response and agrees except that:

1.

The channel check is used following restoration steps to assure that the instrument channel has been restored to its normal configuration, and also to confirm that it has been restored operable.

2.

17-S-01-ll, Performance and System Engineering Instruction Section Level Philosophy, does not appear to be an additional good practice to be employed at will, but appears to be the document that defines how Grand Gulf Surveillance Procedures are written to satisfy the surveillance requirements of the Technical Specifications.

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1 NUMBER:

TEST-02 REVISION: 0 DATE:

4-29-93 1

ASSESSMENT OBSERVATION AREA:

Surveillance Testing INSPECTOR:

W. R. Boyd ISSUE:

Failure to perform adequate logic system functional test of the LPCS RPV injection permissive.

REQUIREMENT:

Technical Specification 4.3.3.2 states " LOGIC SYSTEM FUNCTIONAL TESTS and..... of all channels shall be performed at least once per 18 months."

Technical Specification Definition-l.22 states "A LOGIC SYSTEM FUNCTIONAL TEST shall be a test of all logic components, i.e., all relavs and contacts, all trip units, solid state logic elements, etc., of a logic circuit, from sensor through and including the actuated device, to verify OPERABILITY."

DISCUSSION:

Steps 5.33.10 through 5.33.15 of 06-IC-1B21-R-0003,.Rev. 27, fail to verify each of the RPV low nressure instrument channel relav contacts (E21-K104/K105/K106/K107 contacts M1-TI) in the LPCS injection valve permissive logic actuates as required by Technical Specifications. Verifying that continuity exists (does not exist) only after having tripped (reset) a combination of two instrument channels does not confirm that the individual relay contacts in each instrument channel have actuated. One of the two instrument channel relays could be failed (contact closed) and go undetected because the surveillance procedure does not > quire verification of each individual channel contact. In addition, if the trip unit in the channel with the failed relay trips (resets) before (after) the other trip unit under test, the failure would not be detected by the test method. The surveillance procedure fails to verify that both relays in the selected logic combination are functional.

EXAMPLES:

None.

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NUMBER:

TEST-02 REVISION: 0 Page 2 COMMENTS AS TO SAFETY SIGNIFICANCE:

Failure to perform adequate logic testing could result in an undetected failure. The undetected failure would be in the conservative direction for assuring the injection valve RPV pressure low permissive is provided when needed in response to a LPCS initiation signal and below the injection permissive pressure. However, the undetected failure would also place the logic in a half tripped condition, thereby reducing the protection that prevents the LPCS injection valve from opening when above the injection permissive and increasing the potential for overpressurizing the LPCS piping.

ENTERGY CONTACT:

Rick Ingram ENTERGY RESPONSE:

System Engineering concurs with the observation that one of the two relays could fail in the stuck closed position and go undetected during performance of this surveillance. However, we feel that the current testing verified the sensors, trip units and relays would provide the LPCS Injection Valve Permissive when required. Further, we feel that a failure of any of these relays in the non-conservative mode (contacts would not close) would have been detected by current testing.

Surveillance Procedure 06-IC-1B21-R-0003 will be revised prior to the next schedule performance (11/25/93) to enhance the testing method by monitoring of each logic contact with a DVM to ensure each contact opens and closes when required.

TEAM RESPONSE:

The team has reviewed the Entergy response and agrees with the corrective action.

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NUMBER:

TEST-03 REVISION: 1 DATE:

6/15/93 ASSESSMENT OBSERVATION AREA:

Testing INSPECTOR:

W. R. Boyd ISSUE:

Inadequate post-modification testing of MCP 90/1036.

REQUIREMENT:

Modifications shall be tested to ensure that they perform their design function.

DISCUSSION:

MCP 90/1036 installed two new relays E51-K26 and E51-K27 to initiate the RCIC turbine exhaust line drain trouble annunciator when the RCIC turbine exhaust drain isolation valve E51-F005 fails to open within 5 seconds after the drain pot high-level setpoint has been reached. A special test performed under WO 199001036 was used to demonstrate that the RCIC turbine exhaust line drain level inv umentation performs according to MCP 90/1036.

However, relay E51-K27 (contact M4-T4), which indicates valve F005 position (full open, not full open), was not tested to verify that it performs its design function.

COMMENTS AS TO SAFETY SIGNIFICANCE:

None.

ENTERGY CONTACT:

Rick Ingram ENTERGY RESPONSE:

Entergy agrees with the observation and performed a test that verified that the nelay performs its function. Quality Deficiency Report QDR 93/100 was issued.

TEAM RESPONSE:

The team has reviewed the Entergy response and agrees with the corrective action.

NUMIIER:

M AINT-01 REVISION: 1 DATE:

5/18/93 t-ASSESSMENT OBSERVATION AREA:

Maintenance INSPECTOR:

Robert W. DeNight ISSUE:

Weaknesses identified during RCIC and LPCS system walkdown.

REQUIREMENT: None DISCUSSION:

During the SSFA of the RCIC and LPCS systems, the 'eam conducted a walkdown of these two systems. The weaknesses identified are listed below. Any corrective actions / work orders identified during the assessment are also noted for each example, if applicable.

EXAMPLES:

1.

Discrepant Conditions Oil was leaking from the drain fitting below LPCS pump motor oil level sight glass. Also there appears to be Teflon tape on this fitting.

Insulation is missing from LPCS pump suction piping (near pump).

2.

Maintenance Observations Steam leak on RCIC turbine governor. Already identified on WO 94681.

Valve E51-F010 has packing leakage.

Valve E21-F034 has small amount of packing leakage; packing gland becoming corroded.

Valves P41-F037 and P41-F038 are heavily corroded around packing gland.

l LPCS jockey pump leaking oil from bubbler (appears to be from drainage bolt).

Valve E21-F001 has an ILRT leak test tag attached.

Gauge E51-PT105 is unreadable; gauge glass requires replacement.

NUMBER:

M AINT-01 REVISION: 1 Page 2 Nuts (2 out of 4) on motor supports for fans missing.

Ground wire hanging from overhead conduit coming from insulation, wire was lying on ground wire from motor and conduit.

3.

Housekeeping Concerns 7

A.

LPCS Panel IH22-P001 Lead seals, plastic tubing, and bushings (2) lying in bottom of panel.

B.

LPCS Room Lead seals lying on floor behind suppression pool level transmitters inside LPCS room.

Contact lens case on door near pump.

Floor underneath valve IE21-F001 has various trash, including several pieces of wire and a nut.

Drain cover downstream of E21-F227 has been removed and is lying on floor.

C.

RCIC Room Float switch housing sitting on top of junction box on wall near RCIC pump.

Three pieces of wire on the floor.

1 Stainless steel tubing on Door.

Wire hanger on FT-N003 instrument line.

COMMENTS AS TO SAFETY SIGNIFICANCE:

This observation is not safety significant. It deals with very specific issues, each of which by itself does not have a safety siguificance. However, the aggregate of similar small issues may indicate a broader programmatic weakness.

ENTERGY CONTACT:

Danny Johnson and Kevin Greaves ENTERGY RESPONSE:

The following action has been taken to address your concerns related to RCIC System assessment observations memo dated 4/29/93:

Valve IE51-F10 packing leakage Condition Identification already exists, Cl#33465, 1/26/93 Gauge IE51-PT105 unreadable Condition Identification created 5/11/93, CI#35836

NUMBER:

MAINT-01 REVISION: 1 Page 3 RCIC Room Housekeeping Concerns Arranging Plant Services to address RCIC Room cleanup System Engineering reviewed the SSFA Finding / Concerns noted in MAINT-01 for System E21, and prepared a response to each item as described below:

Component Finding / Concern

Response

Cl Number IE21C001 LPCS pump motor oil level sight CI initiated to 35618 glass leaking oil from drain plug.

investigate and correct Teflon tape appears to be on leakage and check for fitting.

presence of Teflon Tape IE21C001 Insulation missing from LPCS CI initiated to install 35621 pump suction piping insulation IE21F034 Slight packing leakage noted from CI initiated to 35614 valve. Corrosion iloted on packing investigate and correct

gland, leakage, i

P IP41F037 Slight packing leakage noted from CI initiated to 35615 valve. Corrosion noted on packing investigate and correct gland.

leakage.

IP41F038 Slight packing leakage noted from CI initiated to 35616 1

valve. Corrosion noted on packing investigate and correct

gland, leakage.

IE21C002 Slight oil leakage noted from CI initiated to 35617-LPCS jockey pump oil level investigate and correct indicator drain plug.

leakage.

IT51B002 Two nuts missing on fan motor Cl initiated to replace 35613 supports. Loose wire noted from nuts and secure ground overhead conduit that contacted wire.

ground wire on motor.

IE21F001 ILRT test tag installed on valve.

Will be handled as a N/A housekeeping item by Plant Services department.

NUMIIER:

MAINT-01 REVISION: 1 Page 4 Housekeeping concerns will be corrected by the Plant Services Department. No action required by System Engineering at this time.

EVALUATION OF RESPONSE: The team concurs with the response.

OllSERVATION STATUS: This observation is closed.

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NUMIlER:

MAINT-02 REVISION: 2 DATE: -

6/15/93 ASSESSMENT OBSERVATION AREA:

Maintenance INSPECTOR:

Robert W. DeNight -

ISSUE:

Lack of maintenance of the LPCS pump's cyclone separator which could lead to the degradation of the flange seals.

REQUIREMENT:

The cyclone separator should be cleaned and/or inspected during 5-year overhaul intervals, per the pump's vendor manual 460000148.

DISCUSSION:

The LPCS pump has a cyclone separator to provide clean seal water to the pump's flange seals. The seal water is drawn from the discharge of the pump; it then passes through the cyclone separator which removes impurities and permits " clean" seal water to pass to the flange seals. " Dirty" water is drained back to the pump's suction. If the cyclone separator becomes clogged, impure seal water would pass directly to the flange seals. Because the discharge of the cyclone separator is internal to the pump, no drainage can be seen externally. The flange seal damage, if any, from a clogged cyclone separator would only be found during a pump overhaul. However, due to the infrequency of pump overhauls (i.e.,

40 years), the problem could go undetected. The team has been unable to find any records indicating that the separator has ever been cleaned.

COMMENTS AS TO SAFETY SIGNIFICANCE:

This is not of safety significance, because blockage of the cyclone separator will not interfere with pump performance.

ENTERGY CONTACT:

Danny Johnson i

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NUMBER:

MAINT-02 REVISION: 2 Page 2 ENTERGY RESPONSE:

The cyclone separator on the LPCS pump seal piping is intended to remove gross amounts of particulate from the seal water entering the pump mechanical seal. According to the pump manufacturer's manual (460000148) the cyclone separator is designed to remove greater than 96% of all particles larger than 9.5 microns, greater than 94% of all particles larger than 5.0 microns and greater than 85% of all particles larger than 2.5 microns. The pump manufacturer, BWIP, provided the orifice sizes in the cyclone separator to assist in our evaluation. According to BWIP, the orifice sizes in the cyclone separator are 0.44 inches, 0.1360 inches and 0.125 inches, respectively. The LPCS Suction Strainer in the Suppression Pool has screen perforations of 0.1, or 10 meshes per inch.

According to the Tyler standard screen scale,10 meshes per inch will filter all particles 1650 micron and larger (0.065 inches and larger) from the filtered media. GGNS-SDC-E21, Revision 0, E21 System Design Criteria, paragraph 4.3.4, states that the LPCS Suction Strainer and mesh are designed to prevent passage of particles larger than 0,1 inch to prevent clogging of the LPCS main pump cyclone separator. Accordingly, it is unlikely that particles large enough to affect separator performance still enter the separator.

The LPCS pump manufacturer does not specifically require a 5-year inspection frequency for the cyclone strainer. Paragraph 5.4.2 of the manufacturer's pump manual provides general guidance for pump inspection and parts renewal. The manufacturer recommends cleaning of all parts, including the cyclone separator during pump disassembly and inspection, but not as a separate task, to be performed independently on a set frequency. The 5-year frequency referenced in Section 5.4 of the pump manual is consistent and reasonable for maintaining a pump that operates continuously for 5 years. However, the LPCS pump at GGNS is operated for very limited periods of time. For example, we operate the LPCS pump for approximately one hour per quarter and approximately eight hours during refueling outage ECCS testing for a total of approximately 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> during a refueling outage year. During a l

non-outage year, the pump run time will be approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. By projecting the total l

runtime for the LPCS pump over the 40-year life of the plant, the total estimated runtime for this pump is conservatively estimated to be 440 hours0.00509 days <br />0.122 hours <br />7.275132e-4 weeks <br />1.6742e-4 months <br />. This corresponds to approximately 18.33 days of continuous operation. Since LPCS pump runtime is very limited, it is unlikely that cyclone separator maintenance will be necessary after approximately 44 runhours over a 5-year period or after a total service life of 440 hours0.00509 days <br />0.122 hours <br />7.275132e-4 weeks <br />1.6742e-4 months <br /> of operation.

EVALUATION OF RESPONSE: The team concurs with the response.

OBSERVATION STATUS:

This observation is closed.

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1 NUMilER:

MAINT-03 i

REVISION: 2 DATE:

6/15/93 ASSESSMENT OBSERVATION AREA:

Maintenance INSPECTOR:

Robert W. DeNight ISSUE:

Inconsistent torque requirements for RCIC turbine / pump bolts and nuts in various maintenance procedures.

REQUIREMENT:

The bolts of the pump / turbine coupling should be torqued to 20 ft-lb for 3/8-inch bolts or 95 ft-lb for 5/8-inch bolts.

DISCUSSION:

The torque requirements for the RCIC turbine.ud pump coupling are as follows: 20 ft-lb for 3/8-inch bolts and 95 ft-lb for 5/8-inch bolts. This is per the Terry Turbine vendor manual 460000182. The team was notified that the bolts for the coupling are 3/8 inch.

TCN #6 to 07-1-34-E51-C001-2 changed the torque requirements for the coupling bolts from 95 ft-lb to 20 ft-lb; the reason was to modify the torque requirements to reflect 3/8-inch bolts in lieu of 5/8-inch bolts. The modified torque requirement was added to maintenance procedures 07-1-34-E51-C001-2 and 07-1-34-E51-C002-1. However, this requirement was not changed in procedure 07-1-34-E51-C001-1. Step 7.2.27 of this procedure lists various torque requirements for different size bolts, but it does not list torque requirements for 3/8-inch bolts.

The computer system SIMS references 460000946 as the vendor manual for the Unit 1 RCIC pump; however, the correct vendor manual for this component is 460000177. Vendor manual 460000946 is in actuality the vendor manual for the Unit 2 RCIC pump. Because -

both pumps are identical, the two manuals were expected to be the same. However, the torque requirements for the outer case end covers nuts are different. 460000177 states the nuts shall be torqued to 1200 ft-lb, which is the value that is used in the pump overhaul procedure 07-1-34-E51-C001-2; but the Unit 2 RCIC pump manual 460000946 states the torque value is 2250 ft-lb for the identical nut. The team's concern is which is the correct torque value.

NUMBER:

MAINT-03 REVISION: 2 Page 2 COMMENTS AS TO SAFETY SIGNIFICANCE:

This is not of safety significance since RCIC's design function is not directly affected.

However, the improper torque values may be used for the outer case end cover nuts and for the coupling bolts, resulting in higher than required stresses on the bolts and the bolted components. Entergy should ensure that where confusion as to the acceptable torquing i

requirement exists or may have existed, that bolts be checked for proper torque values or that surveillance of the bolts and mating surfaces be performed to ensure early detection of potential degradation of bolting as well as the bolts' components due to higher stresses.

ENTERGY CONTACT:

Kevin Greaves ENTERGY RESPONSE:

This observation is under evaluation.

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NUMBER:

MAINT-04 REVISION: 2 DATE:

6/15/93 ASSESSMENT OBSERVATION AREA:

Maintenance INSPECTOR:

Robert W. DeNight ISSUE:

RCIC pump bearings may not be adequately lubricated prior to start-up of the RCIC bearing.

REQUIREMENT:

The pump vendor manual 460000177 states that if the pump has been stopped for greater than 30 days, it is recommended that the bearings be lubricated by manually turning the pump shaft.

DISCUSSION:

In the extended shutdown section of the pump vendor manual 460000177, page 4-3, it states, if possible, the pump should be started once every 2 weeks and run for 20 to 30 minutes.

However, if it has been stopped for more than 30 days, it is recommended that the bearing be lubricaud, by turning the pump shaft, by hand, in the proper direction of rotation through two or three full revolutions, to coat the bearings with oil. Failure to hand lubricate the bearing before starting the unit could result in damage to the bearings. The RCIC pump and turbine are only run once every 92 days per Operations Procedure 06-OP-1E51-Q-0003. No requirement in this procedure is found to ensure that the bearing lubrication is provided during start-up. If this technique is not performed, the bearings will run for an instant without any lubrication. Bearing wear could result, facilitating the need for additional maintenance to the pump bearings. Bearing wear has been seen in the past overhauls and inspections of the pump. This scenario is not the only source of the bearing wear, but can be a contributing factor.

The RCIC pump also has Dura Seals installed. The operational recommendation for these seals as stated in the pump vendor manual is " Pumps equipped with Dura Seals should be operated for a few minutes every few days." This recommendation should also be evaluated for possible implementation and/or the adequacy of the present 92-day run time intervals on the Dura Seals.

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NUMIIER:

MAINT-04 REVISION: 2 Page 2 COMMENTS AS TO SAFETY SIGNIFICANCE:

The team does not feel that this issue is of safety significance. This observation will not directly affect the designed function of the RCIC system. The worst expected impact on the pump would be potentially more frequent mainterace on the pump bearing due to a decrease in bearing life.

ENTERGY CONTACT:

Kevin Greaves ENTERGY RESPONSE:

For pumps shut down for more than 30 days, the pump vendor manual recommends turning the pump shaft, by hand, through two or three full revolutions to coat the bearings with oil.

Additionally, the manual states failure to hand lubricate the bearings before starting could result in damage to the bearings.

RCIC Surveillance Procedurt 06-OP-lE51-Q-0003 was questioned as to why this hand rotation requirement is not incorporated in this procedure, and infers additional mair.tenance to the pump bearings may be necessitated due to not performing this task.

Rotation of the RCIC Pump by hand prior to the quarterly run is not incorporated in the procedure for the following reasons:

1)

The bearings are inspected on a PM frequency (every 5 years). This equates to approximately 60 hours6.944444e-4 days <br />0.0167 hours <br />9.920635e-5 weeks <br />2.283e-5 months <br /> of pump run time between bearing inspection / replacement.

2)

Work history shows RCIC pump bearings were replaced as a Preventive Maintenance.

activity during RF05 by WO #70547. No mention of excessive bearing wear was stated. The pump bearings were inspected during RF04 by WO #27621 and found to be satisfactory and were not replaced. Previous to the RF04 inspection, the only RCIC pump bearing insp?ction/ replacement was ME0806, dated 11/25/86.

3)

Surveillance Procedure 06-OP-lE51-Q-0003 measures and records pump vibration at two points on the drive end bearing every time the procedure is performed. Pump bearing temperature is measured once every 12 months on both pump bearings.

Therefore, the condition of the pump bearings are continually monitored and excessive pump bearing degradation could be detected.

Based on the above discussion, rotating the pump by hand prior to the quarterly run is unwarranted and would not provide any appreciable benefits with respect to extending the pump bearing life.

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NUMBER:

MAINT-04 i

REVISION: 2 Page 3 EVALUATION OF RESPONSE: The team concurs with the response.

OBSERVATION STATUS:

This observation is closed.

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NUMBER:

MISC-01 REVISION: 2 DATE:

6/15/93 ASSESSMENT OBSERVATION AREA:

Configuration Control INSPECTOR:

Various ISSUE:

Miscellaneous errors identified in design and operating documents.

REQUIREMENT:

ANSI N45.2.11 requires design documentation to accurately reflect plant configuration.

DISCUSSION:

l During the assessment, the team noted numerous errors or inconsistencies in design and operating documents such as system design criteria (SDC), procedures, and drawings EXAMPLES:

E21 SYSTEM DESIGN CRITERIA l

1.

Section 4.4.6. The value of 43 seconds for the analytical LPCS system response time is incorrect. The correct value should be 40 seconds.

2.

Section 6.2.3. The min-flow valve opening requirement is low flow and the pump running instead of just low flow.

3.

Section 6.4.12. The logic as stated in this section is incorrect. The correct logic should be "The valve opening shall be permitted only when a 2 out of 4 pressure condition is signaled." The valves will close only as a result of operator action.

Once closed the valves cannot reopen without a 2 out of 4 low RPV pressure permissive.

E51 SYSTEM DESIGN CRITERIA 1.

System Design Criteria paragraph states that the maximum water temperature for continuous operation shall not exceed 140*F with the stipulation that due to potential short-term operation at higher temperatures, piping expansion calculations shall be based on 170 F. The Technical Specifications Paragraph 3/4.6.3 Bases state that the i

9 NUMBER:

MISC-01 REVISION: 2 Page 2 temperature of the suppresion pool can reach 185*F for post-LOCA long-term peak pool temperature.

t GE DESIGN SPEC DATA SHEETS l.

GE DSDS 22A3125AC, Rev. 8 specifies an analytical LPCS system response time of 43 seconds. Based on the installation of the injection valve opening pressure permissive, ECCS analysis assumes a 30-second stroke time plus 10 seconds for DG start or a total of 40 seconds.

DRAWINGS 1.

Ell 82 sheet 2, the handswitch that is indicated as GE type CR2940-US203E, should be CR2940-YS27El, per DCP 90/0060.

PROCEDURES 1.

The Operations review of DCP/DCIP 90/0060 indicated that no Operations procedures would be impacted by this change. However,06-OP-lE21-Q-0006, Rev.

24, steps 5.3.8c and 5.3.8d will require changes to the acceptable milliamp readings and the pump flow calculations, when this DCP is implemented. This is because the replacement transmitters do not have an internal square root function. This will have to be accounted for in the procedure. The TSTI for this DCP does recognize this and has incorporated the required changes to successfully retest the system.

2.

06-IC-1B21-R-0008, Rev. 27, Attachments I and III,' Data Sheets I, II, and VI, incorrectly identify the Calibration Units with a.E12A prefix. These should be E21 A.

i They are correctly identified as such in the associated Channel Functional Test 06-IC-1B21-M-1007, Rev. 28.

3.

The min / max values (acceptance criteria) provided for the Reactor Vessel Water level Master Trip Unit Analog Meter (IB21-N691 A/B/E/F) in the Channel Functional Test 06-IC-1B21-M-1007 (Rev. 28) differ from that in the Channel Calibration 06-IC-1B21-R-0008 (Rev. 27).

l 4.

The min / max process values (acceptance criteria) provided for trip units 1B21-N691 A/B/E/F and IB21-N692A/B/E/F in Reactor Vessel Water Level (ECCS)

Channel Functional Test 06-IC-1B21-M-1007 (Rev. 28) differ from those provided in i

the Channel Calibration 06-IC-1B21-R-0008 (Rev. 27).

5.

No reference is provided for the setpoints in 06-IC-lE21-M-0001, Rev. 22.

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p NUMBER:

MISC-01 REVISION: 2 Page 3 i

6.

The desired and min / max milliamp (mA) values provided for the LPCS Discharge Line High Pressure Slave Trip Unit IE21-N655 in the Channel Functional Test (06-IC-lE21-M-0001 Rev. 22) differ from those provided in the Channel Calibration (06-IC-1E21-R-0001 Rev. 23).

7.

The basis for the setpoint of the RPV Pressure Low LPCS Injection Permissive is identified as Calculation JC-QlB21-N697-1, Rev. O, in Specification GGNS-1-905.0 Rev. O, " Safety Related instrument Setpoint Calculation Summary." However, these documents are not listed in the reference sections of the associated Channel Functional Test 06-IC-1B21-M-0001 (Rev. 29) and Channel Calibration 06-IC-1B21-R-0003 (Rev. 27).

8.

The minimum acceptable values for the 50% master trip unit analog meter IE51-N636A in the suppression pool high water level channel calibration procedure 06-IC-1E51-R-0003 Rev. 24 differ from those provided in the associated channel functional test procedure 06-IC-1E51-M-0003 Rev. 25.

9.

Procedure 07-S-14-89, which inspects the governor valve, does not check the diametrical clearance. Step 7.7.8 checks only for any interference problems.

Manufacturer's Document No. FDR 45-56800 states that operability problems encountered on the GS-2 turbine governor valve can be caused by improper clearance between the valve plug and the valve guide sleeve. Diametrical clearance must be 5 to 7 mils, preferably toward the high tolerance.

10.

Procedure 07-1-34-E51-C-001-2, steps 7.11.5 through 7.11.7, checks the inner casing clearance. Figure 2, Attachment III in the procedure has reversed the A and B l

dimensions as shown on Figure 11 of the pump vendor manual 460000177. Thus, the specific techniques described in the vendor manual to measure the A and B dimensions will no longer work in the procedure for the switched values.

I1.

Figure 1, Section i1 of the Terry Turbine tech manual, 460000182, still shows the I

first tappet design (ball / tappet) in lieu of the newest molded head design. Installation instructions of the tappet on the figure may not applicable for the new design. Figure 1 of Procedure 04-1-03-E-51-1 also shows the old tappet head design.

12.

Upon review of various work orders, miswritten calibration due dates have been found. The calibration due date for a signal conditioner box (LOO 2) used on CI

1. 26440 is 2/10/92; however the work was performed in May 1992. The calibration due date of B088 used in Cl# 021784 was written as 2/6/92 even though the latest calibration date was 5/6/92.

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NUMBER:

MISC-01 REVISION: 2 Page 5 process head and compare the two process head corrections to select the greater value. The LPCI head correction calculated is greater and more conservative.

4.

As a result of discussions with NPE personnel, it was determined that Calculation 3.3.1 should have been superseded by Calculation 3.3.39-Q. Calculation 3.3.1 has not been superseded and exists in the Document Control system as a valid calculation.

COMMENTS AS TO SAFETY SIGNIFICANCE:

The team is of the opinion that none of the issues listed above is, by itself, a safety significant issue. The issues taken as an aggregate of similar issues may, however, be indicative of a lack of attention to detail.

ENTERGY RESPONSE:

PROCEDURES:

l 2)

System Engineering agrees that the E12A prefix for the Calibration Units should be E21 A in Procedure 06-IC-1B21-R-0008. The reference designation for the Calibration j

Units has been this way since plant start-up and has not been caught by technicians performing the test nor has it caused any problems. A Revision Request will be written to change the designations during the next revision of this procedure.

3)

System Engineering agrees that the acceptance criteria are different but both are correct. The values in one procedure have been changed for readability of the meter while the others represent calculated values. A Revision Request will be written to l

correct the calculated values for meter readabililty during the next revision of this procedure.

4)

System Engineering agrees that the process values are different but both are correct.

The values are different due to rounding by different persons doing calculations some time in the past. A Revision Request will be written to make the values the same

)

during the next revision of this procedure.

J 5)

A Revision Request will be written to reference the proper setpoint calculation documents during the next revision of this procedure.

6)

System Engineering agrees that the mA values are different (0.01 mA) but both are acceptable. The values are different due to rounding by different persons doing calculations some time in the past. A Revision Request will be written to make the values the same during the next revision of this procedure.

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NUMBER:

OPS-01 REVISION: 1 DATE:

6/15/93 ASSESSMENT OBSERVATION AREA:

Operations INSPECTOR:

B. G. Jones /W. R. Boyd ISSUE:

Potential for personnel to become desensitized to conditions requiring corrective action / evaluation.

REQUIREMENT:

Conditions that indicate a component failure or adverse condition should be immediately reported, evaluated for operability, and corrective action initiated.

DISCUSSION:

Review of the completed Auxiliary Building Rounds Sheet (page 12) for May 5, 6, and 7, 1993, indicates that a LPCS Room Sump Pump operated for 18.7,14.7, and 10.4 minutes, respectively. On May 5, Operations started monitoring sump pump operation to try to determine if pump run times were valid or the result of sump level switch failure. On May 7, two days after the sump pump run meter indicated leakage, CI 035694 was initiated to identify sump pump operation and to indicate that failure of the level switch was suspected to be the cause. WO 00096389 was issued on May 12 to troubleshoot LPCS Sump Pump operation.

Sump pump run time could be an indication of leakage as the result of component failure (i.e., pump seals) or relief valve lifting. Any indication of pump run time should be immediately investigated and corrective action initiated. LPCS Room sump level hi-hi alarm is a condition for entry into EP-4.

The team is concerned that the potential exists for Operations personnel to become desensitized to the concerns associated with sump pump operations. In the past 3 years, approximately 9 WOs (01707, 34515,14560, 26947, 42754, 51557, 53397, 55845, and 55847) have been initiated to investigate and repair 13 sump pump timers. In addition,7 WOs (86391, 44086, 91609, 22442, 75286, 26645, and 20410) were initiated to investigate and repair 11 sump level switches. On May 5, when the LPCS Sump Pump run timer i

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NUMBER:

OPS-01 REVISION: 1 l

Page 2 i

indicated that the pump had rtm for 18.7 minutes (approximately 1,800 gallons), the actions l

taken (inquire if Radwaste had noticed an unusual influx and to monitor LPCS sump pump.

operation on the BOP computer) were to try to verify if the timer indication was valid or if it was just another timer or level switch problem. In addition, when the Operations department was questioned regarding the threshold for taking investigative or corrective action associated with the LPCS Room Sump Pump operation, the response was speculative that " Stuck sump level switches are not uncommon."

In addition, the LPCS (E21) System Design Criteria, Rev. O, Section 4.2.4 states "The LPCS pump shall be provided with a small lenkoff line to drain seal leakage. This line shall permit measurement and visual inspection of any leakage." During a ws.lkdown of the system, such a leakoff line with the ability to permit measurement or visual examination was not found.

Operations informed the team that the only means they have of detecting or measuring leakage is by monitoring operation of the sump pumps and radwaste inleakage.

COMMENTS AS TO SAFETY SIGNIFICANCE:

Because there are other alert indications, such as an increase in the amount of liquiu radwasta, that should alert the operators to determine the source of leakage, it is not believed.

that this panicular issue is of safety significance. However, the broader issue of desensitization of the operators as a result of long standing maintenance or operations issues should be of greater concern. The team recommends an assessment of whether similar long-term maintenance and operations issues exist, to ensure that desensitization is not occurring.

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NUMBER:

MISC-01 REVISION: 2 Page 4 UFSAR 1.

UFSAR Section 5.4.6.2.2.2.K, Instrument Setpoints, item - Cmdensate Storage Tank Ixw Level, Note (3) on page 5.4-50, indicates that at 0 inches in the CST there is a minimum of 875 gallons in the tank for RCIC. This should be 11,000 gallons.

2.

UFSAR Section 5.4.6.2.2.2.k-, Instrument Setpoints, I:cm - Drain pot high, the l

required accuracy stated is i 0.2 inch of set point. In actuality, the set point i

accuracy is 0.25 inch (nominal) and 0.5 inch (max) in procedures 07-S '

E51-7 and 07-S-53-E51-4. In addition, the reset deadband is 0.5 inch in the UFSAR and 0.8 inch in the field.

3.

Table 7.3-4 LPCS pump discharge pressure reads 0-500 psig. It should be 0-300 psig.

4 Table 7.4.1 RCIC system pump high/ low suction pressure should read 30 in Hg to 100 psig instead of 30 in Hg.

5.

Table 7.4.1 RCIC steam supply low pressure should read 0-1500 psig, instead of l

0-200 psig.

6.

The UFSAR lists the cooling requirements for both the LPCS and the RCIC room.

These values differ from the values found in a calculation. For instance, the UFSAR states the RCIC room heat load to be 43,306 BTUH, whereas Calculation 3.3.39-Q

tates this value to be 6,646 BTUH. Similarly for the LPCS room, the UFSAR states the cooling load to be 243,724 BTUH, whereas the calculation states this value as 241,005 BTUH.

CALCULATIONS 1.

In EC-QlL21-90033 Rev. O, sheet i1, the subscripts on the calculated minimum voltages are reversed.

2.

JC-QlE51-N651-2, " Min RCIC pump bypass control - flow" Section 7.0 " conclusion" should read bypass valve may not open instead of bypass valve may not close.

3.

JC-QlB21-N697-1 Rev. O " Low pressure ECCS pressure permissi e setpoint calculation." Section 5.10, step 9, calculates only the process head correction for the LPCI injection line, whereas the transmitter PT-N608 provides a signal to the LPCS and LPCI control. Note 4 of the GE DSDS 22A3856AA specifies that the larger of the two pressures should be used. The calculation does not calculate the LPCS s

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• i NUMBER:

MISC-01 REVISION: 2 Page 6 7)

A Revision Request will be written to reference the proper setpoint calculation documents during the next revision of this procedure.

8)

This appears to be a typographical error since the Desired is 15 and the Min is 15.

For IE51-N636B the Desired is 15 and the Min is 14 as it should be. A Revision-Request will be written to correct this typo during the next revision of this procedure.

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